Callon Petroleum Co - FORM 8-K/A - EX-99.2

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EX-99.1 - EX-99.1 - Callon Petroleum Co	cpe-20170213xex99_1.htm
EX-23.1 - EX-23.1 - Callon Petroleum Co	cpe-20170213xex23_1.htm
8-K/A - 8-K/A - Callon Petroleum Co	cpe-20170213x8ka.htm

Exhibit 99.2

CALLON PETROLEUM COMPANY, INC.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

On February 13, 2017, Callon Petroleum Operating Company, a wholly owned subsidiary of Callon Petroleum Company (“Callon” or the “Company”) completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, (the “Acquired Properties”) for total cash consideration of $632.9 million, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company acquired an 82% average working interest in the properties acquired in the Ameredev Transaction.

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock (the “Equity Offering”) for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634.9 million which was used to fund the Ameredev Transaction.

On October 20, 2016, the Company completed the acquisition of 6,904 gross (5,952 net) acres primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339.7 million, excluding customary purchase price adjustments (the “Plymouth Transaction”).

On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220 million and 9,333,333 shares of common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329.6 million, excluding customary purchase price adjustments (the “Big Star Transaction”).

We derived the unaudited pro forma consolidated financial statements from the historical consolidated financial statements of the Company and the Combined Schedules of Revenues and Direct Operating Expenses for the Acquired Properties, Plymouth Transaction, and the Big Star Transaction for the respective periods. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 give effect to the Ameredev Transaction and Equity Offering as if they occurred on January 1, 2016. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 give effect to the Plymouth Transaction and Big Star Transaction as if they occurred on January 1, 2015. The unaudited pro forma consolidated balance sheet as of December 31, 2016 gives effect to the Ameredev Transaction as if it occurred on December 31, 2016.

The pro forma adjustments are based on available information and certain assumptions that we believe are reasonable as of the date of this Current Report on Form 8-K/A. Assumptions underlying the pro forma adjustments related to the Acquired Properties, Plymouth Transaction and Big Star Transaction are described in the accompanying notes, which should be read in conjunction with the unaudited pro forma consolidated statement of operations. The pro forma adjustments reflected herein are based on management’s expectations regarding the Acquired Properties, Plymouth Transaction and Big Star Transaction discussed above.

The unaudited pro forma consolidated financial statements are presented for illustrative purposes only and do not purport to indicate the financial condition or results of operations of future periods or the financial condition or results of operations that actually would have been realized had the Ameredev Transaction, Plymouth Transaction, Big Star Transaction, and Equity Offering been consummated on the dates or for the periods presented. The unaudited pro forma consolidated financial statements should be read in conjunction with (1) the audited December 31, 2016 consolidated financial statements, and notes thereto, contained in the Company’s Annual Report on Form 10-K, filed on February 27, 2017; (2) the unaudited pro forma statement of operations for the Big Star Acquisition for the six months ended June 30, 2016, filed with the Company’s Current Report on Form 8-K on September 6, 2016; (3) the unaudited pro forma statement of operations for the Plymouth Transaction for the nine months ended September 30, 2016, and the unaudited pro forma statement of operations for the Plymouth Transaction and the Big Star Transaction for the year ended December 31, 2016, filed with the Company’s Current Report on Form 8-K on April 13, 2017, and; (4) the Combined Schedules of Revenues and Direct Operating Expenses for the year ended December 31, 2016, filed as Exhibit 99.1 with this Current Report on Form 8-K/A. The unaudited pro forma consolidated statement of operations should be read in connection with the Company’s Current Reports on Form 8-K/A, filed on August 4, 2016, and on Form 8-K filed on April 19, 2016 and May 31, 2016, which provide a more complete description of the Big Star Transaction. The unaudited pro forma consolidated statement of operations should be read in connection with the Company’s Current

Report on Form 8-K filed on September 6, 2016, October 25, 2016, and Form 8-K/A, filed on December 13, 2016, which provide a more complete description of the Plymouth Transaction.


CALLON PETROLEUM COMPANY
Unaudited Pro Forma Consolidated Balance Sheet
as of December 31, 2016
($ in thousands, except share data)

	Historical		Acquired Properties			Pro forma
ASSETS
Current assets:
Cash and cash equivalents	$	652,993	$	(586,809)	b	$	66,184
Accounts receivable		69,783		—			69,783
Fair value of derivatives		103		—			103
Other current assets		2,247		—			2,247
Total current assets		725,126		(586,809)			138,317
Oil and natural gas properties, full-cost accounting method:
Evaluated properties		2,754,353		134,315	a		2,888,668
Less accumulated depreciation, depletion and amortization		(1,947,673)		—			(1,947,673)
Net oil and natural gas properties		806,680		134,315			940,995
Unevaluated properties excluded from amortization		668,721		498,800	a		1,167,521
Total oil and natural gas properties		1,475,401		633,115			2,108,516
Other property and equipment, net		14,114		—			14,114
Restricted investments		3,332		—			3,332
Deferred financing costs		3,092		—			3,092
Acquisition deposit		46,138		(46,138)	b		—
Other assets, net		384		—			384
Total assets	$	2,267,587	$	168		$	2,267,755
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	95,577	$	—		$	95,577
Accrued interest		6,057		—			6,057
Cash-settleable restricted stock unit awards		8,919		—			8,919
Asset retirement obligations		2,729		—			2,729
Fair value of derivatives		18,268		—			18,268
Total current liabilities		131,550		—			131,550
Senior secured revolving credit facility		—		—			—
Secured second line term loan, net of unamortized deferred financing costs		390,219		—			390,219
Asset retirement obligations		3,932		168	a		4,100
Cash-settleable restricted stock unit awards		8,071		—			8,071
Deferred tax liability		90					90
Fair value of derivatives		28		—			28
Other long-term liabilities		295		—			295
Total liabilities		534,185		168			534,353
Commitments and contingencies
Stockholders' equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 shares outstanding		15		—			15
Common stock, $0.01 par value, 300,000,000 shares authorized; 201,041,320 shares outstanding		2,010		—			2,010
Capital in excess of par value		2,171,514		—			2,171,514
Accumulated deficit		(440,137)		—			(440,137)
Total stockholders' equity		1,733,402		—			1,733,402
Total liabilities and stockholders' equity	$	2,267,587	$	168		$	2,267,755


CALLON PETROLEUM COMPANY
Unaudited Pro forma Consolidated Statements of Operations for the Year Ended December 31, 2016
($ in thousands, except share data)

						Adjustments						Adjustments						Adjustments
			Big Star			(Big Star			Plymouth			(Plymouth			Acquired			(Acquired
	Historical		Transaction			Transaction)			Transaction			Transaction)			Properties			Properties)			Pro forma
Operating revenues:
Oil sales	$	177,652	$	*		$	—		$	*		$	—		$	*		$	—		$	*
Natural gas sales		23,199		*			—			*			—			*			—			*
Total operating revenues		200,851		9,200	c		—			15,275	d		—			17,947	e		—			243,273
Operating expenses:
Lease operating expenses		38,353		2,193	c		—			1,601	d		—			5,274	e		—			47,421
Production taxes		11,870		590	c		—			927	d		—			736	e		—			14,123
Depreciation, depletion and amortization		71,369		—			6,349	c		—			6,404	d		—			10,628	f		94,750
General and administrative		26,317		—						—			—			—			—			26,317
Accretion expense		958		—			(27)	c		—			(8)	d		—			8	f		931
Write-down of oil and natural gas properties		95,788		—			—			—			—			—			—			95,788
Acquisition expense		3,673		—			—			—			—			—			—			3,673
Total operating expenses		248,328		2,783			6,322			2,528			6,396			6,010			10,636			283,003
Income from operations		(47,477)		6,417			(6,322)			12,747			(6,396)			11,937			(10,636)			(39,730)
Other (income) expenses:
Interest expense		11,871		—			(6,760)	c		—			(726)	d		—			(1,264)	g		3,121
Loss on early extinguishment of debt		12,883		—			—			—			—			—			—			12,883
Loss on derivative contracts		20,233		—			—			—			—			—			—			20,233
Other income, net		(637)		—			—			—			—			—			—			(637)
Total other expenses		44,350		—			(6,760)			—			(726)			—			(1,264)			35,600
Income (loss) before income taxes		(91,827)		6,417			438			12,747			(5,670)			11,937			(9,372)			(75,330)
Income tax expense (benefit)		(14)		—			—			—			—			—			—	h		(14)
Net income (loss)		(91,813)		6,417			438			12,747			(5,670)			11,937			(9,372)			(75,316)
Preferred stock dividends		(7,295)		—			—			—			—			—			—			(7,295)
Income (loss) available to common
stockholders	$	(99,108)	$	6,417		$	438		$	12,747		$	(5,670)		$	11,937		$	(9,372)		$	(82,611)
Income (loss) per common share:
Basic	$	(0.78)																			$	(0.50)
Diluted	$	(0.78)																			$	(0.50)
Shares used in computing income (loss) per
common share:
Basic		126,258																	40,000	i		166,258
Diluted		126,258																	40,000	i		166,258

*Pro forma operating revenues did not separately break out oil and natural gas sales.

1. Basis of Presentation

We derived the unaudited pro forma consolidated financial statements from the historical consolidated financial statements of the Company and the Statements of Revenues and Direct Operating Expenses for the Acquired Properties, Plymouth Transaction, and the Big Star Transaction for the respective periods. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 give effect to the Ameredev Transaction and the Equity Offering as if they occurred on January 1, 2016. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2016 give effect to the Plymouth Transaction and the Big Star Transaction as if they occurred on January 1, 2015. The unaudited pro forma consolidated balance sheet as of December 31, 2016 gives effect to the Ameredev Transaction as if it occurred on December 31, 2016.

The unaudited pro forma consolidated financial statements are presented for illustrative purposes only and do not purport to represent what the Company’s financial position or results of operations would have been if the Ameredev Transaction, Plymouth Transaction and the Big Star Transaction had occurred as presented, or to project the Company’s financial position or results of operations for any future periods. The pro forma adjustments related to the Acquired Properties, Plymouth Transaction and the Big Star Transaction are based on available information and certain assumptions that management believes are reasonable. The pro forma adjustments are directly attributable to the Acquired Properties, Plymouth Transaction and the Big Star Transaction and are expected to have a continuing impact on the Company’s results of operations. In the opinion of management, all adjustments necessary to present fairly the unaudited consolidated pro forma financial statements have been made.

2. Preliminary Purchase Accounting

The Ameredev Transaction closed on February 13, 2017 for an aggregate purchase price of $632.9 million in cash, subject to customary post-closing adjustments. The Ameredev Transaction will be accounted for using the purchase method of accounting. Accordingly, the assets acquired and liabilities assumed are presented based on their estimated acquisition date fair values. The purchase price allocation relating to the Acquired Properties below is preliminary and based on management’s best estimates as of the date of this Current Report on Form 8-K/A. The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.

The following table summarizes the estimated acquisition date fair values of the net assets acquired in the Acquired Properties (in thousands):


Evaluated oil and natural gas properties	$	134,315
Unevaluated oil and natural gas properties		498,800
Asset retirement obligations		(168)
Net assets acquired	$	632,947

3. Pro Forma Adjustments

Unaudited Pro forma Consolidated Balance Sheet as of December 31, 2016

(a)

To record the estimated fair value of the assets acquired and the liabilities assumed in the acquisition.

(b)

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634.9 which was used to fund the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46.1 million to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016.

Unaudited Pro forma Consolidated Statements of Operations for the year ended December 31, 2016

(c)

To record the historical revenues and direct operating expense and pro forma adjustments related to the Big Star Transaction previously reported in the Company’s Current Report on Form 8-K/A filed on August 4, 2016, on Form 8-K filed on September 6, 2016, and on Form 8-K/A filed on April 13, 2017.

(d)

To record the historical revenues and direct operating expense and pro forma adjustments related to the Plymouth Transaction previously reported in the Company’s Current Report on Form 8-K/A filed on December 13, 2016 and April 13, 2017.

(e)

To record the historical revenues and direct operating expense related to the Acquired Properties.

(f)

To record depreciation, depletion, and amortization and accretion related to the Acquired Properties.

(g)

To record a $1.3 million adjustment to estimated interest costs capitalized to unevaluated oil and gas properties. The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense.

(h)

The Company typically provides for income taxes at a statutory rate of 35%, but as a result of the write-downs of oil and natural gas properties recognized in the third and fourth quarters of 2015, the Company has incurred a cumulative three year loss resulting in no income tax expense.

(i)

4. Supplemental Oil and Gas Disclosures

The following table sets forth unaudited pro forma information with respect to the Company’s estimated proved reserves, including changes therein, and proved developed and proved undeveloped reserves for the year ended December 31, 2016, giving effect to the Ameredev Transaction as if it had occurred on January 1, 2016. The estimates of reserves attributable to the Ameredev Transaction may include development plans for those properties which are different from those that the Company will ultimately implement. Reserve estimates are inherently imprecise, require extensive judgments of reservoir engineering data and are generally less precise than estimates made in connection with financial disclosures.


	Changes in Reserve Quantities
	Historical	Acquired Properties (a)	Pro forma
Proved developed and undeveloped reserves:
Oil (MBbls):
Proved reserves as of December 31, 2015	43,348	5,562	48,910
Revisions to previous estimates	(5,738)	(249)	(5,987)
Purchase of reserves in place (net of sales)	23,336	—	23,336
Extensions and discoveries	14,479	3,805	18,284
Production	(4,280)	(371)	(4,651)
Proved reserves as of December 31, 2016	71,145	8,747	79,892
Natural Gas (MMcf):
Proved reserves as of December 31, 2015	65,537	8,855	74,392
Revisions to previous estimates	13,929	(668)	13,261
Purchase of reserves in place (net of sales)	33,709	—	33,709
Extensions and discoveries	17,194	5,640	22,834
Production	(7,758)	(362)	(8,120)
Proved reserves as of December 31, 2016	122,611	13,465	136,076

(a)

Proved reserves related to NGL volumes for the Acquired Properties are included in natural gas volumes.

The following tables present the unaudited pro forma standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by ASC Topic 932, for the year ended December 31, 2016, giving effect to the Ameredev Transaction as if it had occurred on January 1, 2016. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate. We have assumed the federal tax rate of 35% on the Acquired Properties. The disclosures below do not purport to present the fair market value of the Company’s oil and gas reserves. An estimate of the fair market value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.


		Standardized Measure
		For the Year Ended December 31, 2016
	Historical			Acquired Properties	Pro forma
Future cash inflows	$	3,180,005	$	348,711	$	3,528,716
Future costs -
Production		(974,667)		(126,309)		(1,100,976)
Development and net abandonment		(384,117)		(61,250)		(445,367)
Future net inflows before income taxes		1,821,221		161,152		1,982,373
Future income taxes		(1,602)		(17,319)		(18,921)
Future net cash flows		1,819,619		143,833		1,963,452
10% discount factor		(1,009,787)		(79,536)		(1,089,323)
Standardized measure of discounted future net cash flows	$	809,832	$	64,297	$	874,129

The following table presents unaudited pro forma changes in the standardized measure of discounted future net cash flows for the year

ended December 31, 2016 relating to proved oil and natural gas reserves of the Company and the Acquired Properties.


		Changes in Standardized Measure
		For the Year Ended December 31, 2016
	Historical			Acquired Properties	Pro forma
Standardized measure at the beginning of the period	$	570,890	$	53,621	$	624,511
Changes
Sales and transfers, net of production costs		(150,628)		(11,465)		(162,093)
Net change in sales and transfer prices, net of production costs		(103,136)		(13,318)		(116,454)
Net change due to purchases and sales of in place reserves		260,859		—		260,859
Extensions, discoveries, and improved recovery, net of future
production and development costs incurred		180,228		33,923		214,151
Changes in future development cost		82,320		(7,760)		74,560
Revisions of quantity estimates		(35,938)		(3,413)		(39,351)
Accretion of discount		57,091		6,520		63,611
Net change in income taxes		16		7,939		7,955
Changes in production rates, timing and other		(51,870)		(1,750)		(53,620)
Aggregate change		238,942		10,676		249,618
Standardized measure at the end of period	$	809,832	$	64,297	$	874,129

The historical twelve-month average prices of oil and natural gas used in determining standardized measure as of December 31, 2016, were:


			Acquired
	Historical		Properties
Average 12-month price, net of differentials, per Mcf of natural gas	$	2.71	$	1.87
Average 12-month price, net of differentials, per barrel of oil	$	40.03	$	36.99

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